Rice Energy Investor Presentation - August 11, 2014

1 www.riceenergy.com

Second Quarter 2014 Investor PresentationAugust 11, 2014


COMPANY TOTAL

OHIO

PENNSYLVANIA

~127,000 net acres in Appalachia 280 MMcf/d net June production from 55 wells 61 operated wells in progress 1,033 net risked locations Average horizontal rigs for 2014: 3

~51,000 net acres, <1% developed 1 producing Utica well (Bigfoot 9H) 10 operated Utica wells in progress 246 net risked Utica locations

~76,000 net acres, <5% developed 54 producing wells (51 Marcellus, 3 Upper Devonian) 51 operated Marcellus wells in progress 526 net risked Marcellus locations 261 net risked Upper Devonian locations

__________________________Note: Approximately 55,000 net acres in the Marcellus Shale is also prospective for the Geneseo (Upper Devonian) Shale. The Upper Devonian and the Marcellus Shale are stacked formations within the same geographic footprint. See slide entitled “Additional Disclosures” on detail regarding Rice’s methodology for the calculation of net unrisked and risked locations

Rice Energy – Concentrated Core Position

RICE FT & MIDSTREAM

FT: ~1 Bcf/d firm capacity contracted, 70% to Gulf Coast and Midwest marketsMidstream: YE2015 throughput capacity of ~ 4.5 Bcf/d


43,978 75,834

46,700

50,772 90,678

Q4 2013 Q2 2014Marcellus Utica

126,606

De-risk production growth, neutralize basis volatility, maximize cash marginsSubstantial Growth to Low-Risk Drilling Inventory

Production Growth from High Rate of Return Projects

Securing Additional Access to Premium Markets

Net Core Acreage

325 526

233

246 558

772

Q4 2013 Q2 2014Marcellus Utica

Net Risked Locations

174

262

Q4 2013 Q2 2014

Net Producing Lateral Feet (000s)

154

241

Q4 2013 Q2 2014

Net Production (MMcf/d)

IPO CurrentAppalachia Non-Appalachia

756,000918,000

671,000591,000

165,000 247,000

2016 Firm Transport

Marcellus development on point + exciting initial results from the Utica

36,000 net acres added, 100% within existing areas of operations

Delivering on Our Plan Since IPOAccomplishments Since IPO

Increased production by ~60% since year-end 2013- Turned online 14 Marcellus wells, avg ~8,000’ hz, 30 day avg ~ 13 MMcf/d

Drilled the biggest well in the Utica- Bigfoot 9H tested at 42 MMcf/d @ 5850 psi- Producing into sales above type curve

Meaningfully added to our core acreage position- Leased ~14,000 net acres + acquired 22,000 net acres (~90% PA, ~10% OH)

Secured add’l firm transport to premium markets- Added 275,000 dth/d with access to Gulf Coast, Midwest and Canadian markets

Invested in our midstream to grow our bottom line- Acquired Momentum Marcellus gathering system for $110MM- Constructing 1.0 bcf/d Marcellus header system with FT to Gulf Coast

Basis Exposure (2015-2016)

36%

64%

2015

47%53%

2016

(1)

__________________________1. Includes volumes in excess of firm transportation. Non-Appalachian exposure includes TCO


Disciplined approach to increasing core acreage is transformative to our low risk, high return inventory– Our asset value is not static and will continue to grow

By the end of 2014, we expect to have added ~50,000 net acres through organic leasing (~28,000) and the Greene County Acquisition (22,000)

Core Acreage Growth Since 2011

Proven Ability to Grow Core Position


5.3

2.1

4.8

1.1

2.8

0

100

200

300

400

500

600

700

0% 20% 40% 60% 80% 100% 120% 140%

Net Unrisked Drilling Locations

Single Well Pre-Tax IRR %

Deep Inventory of High Returning Projects

Ohio Utica Dry

OhioUtica Wet

Marcellus

Western Greene Marcellus

Geneseo

Bubble Size indicates net potential reserves, Tcf

Marcellus: 750 net unrisked drilling locations with 60-110% IRR; type curve de-risked by 50+ producing Marcellus wells Ohio Utica: 339 net unrisked drilling locations with 70-120% IRR; first Utica well, Bigfoot 9H, tracking above budgeted EURs Upper Devonian: 406 net unrisked drilling locations with 20-30% IRR PA Utica: To be determined

16 Tcf of net undeveloped potential reserves – Average 86% IRR to develop 13.3 Tcf from Marcellus and Utica

IRR difference driven by historical gathering fee


Pennsylvania Assets


AU2 Pad – 2 WellsAvg 180 Day IP: 8.8 MMcf/dAvg Lateral Ft: 5,921’

Allegheny

Washington

Greene

Rice Energy AcreageRice Energy AcreageRice Energy Acreage

X-Man Pad – 2 WellsAvg 180 Day IP: 12.8 MMcf/dAvg Lateral Ft: 7,410’

Thunder 2 Pad – 2 WellsAvg 180 Day IP: 12.0 MMcf/d Avg Lateral Ft: 9,006’

Lusk Pad – 2 WellsAvg 180 Day IP: 10.2 MMcf/dAvg Lateral Ft: 5,780’

Brova 1HAvg 180 Day IP: 9.5 MMcf/dLateral Ft: 3,552’

Big Daddy Pad – 2 WellsAvg 180 Day IP: 6.7 MMcf/dAvg Lateral Ft: 3,150’

Hulk Pad – 3 WellsAvg 180 Day IP: 14.5 MMcf/dAvg Lateral Ft: 9,000’

Mono 4HAvg 556 Day IP: 10.3 MMcf/d5.7 Bcf produced in 18 monthsLateral Ft: 6,233’

Whipkey 1HAvg 180 Day IP:10.5 MMcf/dAvg Lateral Ft: 6,655’

Wayne Pad – 4 WellsAvg 180 Day IP:11.1 MMcf/dAvg Lateral Ft: 6,691’

Amigos Pad – 3 WellsAvg 180 Day IP: 12.2 MMcf/dAvg Lateral Ft: 6,317’

Acreage: 75,834 net acres in the southwestern core (100% operated)– 80% held by production or does not expire until

2017+

Inventory: 787 total net risked identified drilling locations, 526 in the Marcellus and 261 in the Upper Devonian

Operations: Well results from 51 producing horizontal Marcellus wells as of June 30, 2014 51 additional Marcellus wells currently in

progress

Marcellus Overview

_________________________1. Figures represent pro forma impact from Greene County Acquisition.

Marcellus Well ResultsSummary (1)

Sustained prolific production rates over a 6-month period

Marcellus Well Results To Date

Wells Turned Avg. Lateral Flow Rates (MMcf/d) D&CYear(s) To Sales Length 0-90 0-120 0-180 ($/Ft)2010-2011 6 3,281 5.7 5.8 5.8 2,377$ 2012 9 5,731 9.2 9.7 9.6 1,663$ 2013 22 6,286 11.2 11.2 10.9 1,469$ 1Q 2014 4 6,691 12.7 12.2 11.1 1,348$ 2Q 2014 10 8,452 12.9 NA NA 1,243$

Total 51 6,291 10.4 10.2 9.9 1,556$

* Flow rates based on wells with available history

Producing PadPad in Progress


0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

9.0

- 200 400 600 800 1,000 1,200 1,400 1,600 1,800

Unmatched Well Performance

__________________________1. Data for Rice Energy based on actuals through 7/31/14, peer data based on Pennsylvania Department of Environmental Protection production reports through December 31, 2013.

Rice’s drilling and completion techniques have yielded greater production profile per well, versus our peers

Washington & Greene Counties Cumulative Production vs. Time (1)

Cumulative Production (Bcfe)

Days Online

Average 90-Day IP, MarcellusDrilling Proficiency, MarcellusMMcf/d

5.7

9.2

11.2 12.7 12.9

2010-2011 2012 2013 1Q14 2Q14

3,281

5,731 6,286 6,691

8,452 15.8

7.6 5.8

4.5 4.5

–2.04.06.08.010.012.014.016.018.0

–1,0002,0003,0004,0005,0006,0007,0008,0009,000

2010-2011 2012 2013 1Q14 2Q14

Avg. Lateral Ft. Avg. Hz. Drilling Days

Rice Washington CountyRice Greene CountyRice GeneseoPeer Marcellus


__________________________1. See slide entitled “Additional Disclosures” on detail regarding Rice’s methodology for the calculation of net unrisked and risked locations.2. Terms being finalized. Historical gathering and compression rate of $0.45/Mmbtu and $0.12/Mmbtu.

We have closed on our previously announced acquisition of 22,000 net acres in the core the SW PA Marcellus

Greene County Acquisition Summary

Rice Pro Forma Acreage MapTransaction ProfileAcreage Summary 22,000 net acres, 100% operated, average 82% NRI ~70% acreage is either HBP or expires in 2017+Marcellus – 22,000 net acres ~20 MMcf/d net from 7 producing wells; 5 wells in progress 152 risked / 190 unrisked net drilling locations (1), avg ~7,000’ lateral 1,080-1,100 Btu/Scf Reserve profile similar to Rice’s Marcellus wells in SW PA Commence pad-drilling in first half of 2015Utica – 14,000 net acres Expecting 1,020-1,040 Btu/Scf Initial test in 1H 2015Geneseo (Upper Devonian) – 18,500 net acres 135 unrisked net drilling locations (1), avg ~7,000’ lateral Expecting 1080-1100 Btu/Scf Initial test in 2016Midstream Acreage dedicated to Access Midstream No processing neededKey Terms/Dates Closed on 8/1/14 Rice Acreage

Western Greene County Acquisition


($2.0)

–

$2.0

$4.0

$6.0

$8.0

$10.0

$12.0

$14.0

–

20%

40%

60%

80%

100%

120%

140%

160%

180%

200%

$3.00 $3.50 $4.00 $4.50 $5.00IRR NPV-10

__________________________Note: Production data through 7/21/14, data normalized to 5,900’ lateral (average lateral length of Rice’s seven producing horizontal wells in western Greene County, PA).

Rice Well Performance, Western Greene Resource Potential & NAV

Whipkey Pad

Amigos Pad

Acquisition of a De-risked, High-Return Marcellus Position

Resource Risked UnriskedNet Locations 152 190

Value ($mm)Single-Well PV-10 (at $4 HHUB) $6.1 $6.1Undeveloped Acreage Value $927 $1,159PDP Value $75 $75Total Value Potential $1,002 $1,234Purchase Price $336 $336

Single Well PV-10 ($MM) and IRR

7%26%

$0.7

$2.7

$6.1

$9.6

$13.0

58%

107%

180%

Trans Energy2.0 BCFE/1000’

Chesapeake

Vantage2.2 BCF/1000’

22,000 Acre Acquisition

Rice has had considerable success from its development on trend and in close proximity to the acquired acreage.

0.0

1.0

2.0

3.0

4.0

5.0

0 100 200 300 400 500

Bcf

Days

Whipkey and Amigos Pads

5.0

4.0

1-Year


Rice Acreage

Deep Utica Potential in Pennsylvania

Porosity in southeast OH extends into southwest PA– Belmont Washington– Monroe Greene

Thick, high pressure and high porosity Utica section in southwest PA at depths between 12,000-13,000’ TVD

– Industry tests underway in SW PA from multiple operators We plan to spud our first PA Utica well in early 2015

– To be located on our recently acquired acreage in western Greene County

East

EQTPreparing

RangeIn Progress

Rice (PA)Permitting

West

OH WV

RICE: ~50k acresin central Belmont

40+ MMcf/d IP1050-1150 BTU

RICE: ~15k acresin western Greene

2015 Test1020-1040 BTU

12,000 – 13,000’9500’7500’5000’ 6000’County

0%

6%

12%Porosity

Peer Avg20-40 MMcfe/d1150-1250 BTU

Peer Avg5-15 MMcfe/d IP1250-1350 BTU

MuskingumFairfield Guernsey Belmont Ohio/Marshall Washington / Greene10,500’Depth

PA

Point Pleasant Core


Net Unrisked Locations 560NRI Hz Ft. Inventory 2.7mm ft.PV-10 ($mm) $ 8.5IRR 104 %Undiscounted Payback 1.0 yrsD&C ($mm) $ 8.0Type Curve Assumptions120-Day IP (MMcf/d) Pre-Processed 13.4Bcf / 1000' 1.94Average Lateral Length 6,000NGL Yield (Bbls / MMcf) - Gas Mmbtu (Pre-Processed) 1,050Gas Shrink 0 %Gross EUR (Bcfe, Post-Processing) 11.6% Gas 100 %

0

2

4

6

8

10

12

14

16

0.0 yrs 0.5 yrs 1.0 yrs 1.5 yrs 2.0 yrs 2.5 yrs 3.0 yrs

MMcf/d

Actual Production - Historical Average NSAI - 6,000' Lateral

Type Well Economics(2)

1.94 Bcf / 1,000’ Type Curve (1)

IRR Sensitivity (3)

30%61%

104%

162%

236%

52%77% 135%

169%

$3.00 $3.50 $4.00 $4.50 $5.000%

50%

100%

150%

200%

250%

NYMEX ($ / MMBtu)

Rice’s Marcellus Shale Type Curve

___________________________1. Represents gross type curve. Actual production is normalized to 6,000’ laterals. Normalized production excludes six wells; five due to suboptimal spacing to offset producing wells and one well excluded because majority of lateral was drilling in suboptimal zone

(second Marcellus well in Company’s history). Data has been adjusted to reflect only producing days.2. Based on $4.00/MMBtu and 100% WI. Net horizontal feet calculation based on net revenue interest assuming a 18.5% average royalty interest in the Marcellus. Excludes Greene County Acquisition. Includes 190 unrisked locations from Greene County

acquisition. Based on historical gathering and compression fees, single well PV-10 of $6.1mm and single well IRR of 58%.3. IRR is net to Rice’s ownership interest. Hedged IRR assumes 50% of production hedged at $4.00/MMBtu in the first year and 25% of production hedged at $4.00/MMBtu in the second year.

All wells are produced on restricted choke program

Hedged IRRUnhedged IRR

7503.7mm ft


Ohio Assets


__________________________1. Data per RigData as of August 6, 2014.

Growth and Development The Utica play as a whole has contracted to the

Southern Utica Core, which has delivered some of the highest volume shale wells in North America

Rice controls 50,772 acres concentrated in the heart of the core in Belmont County, surrounded on all sides by robust results

Rice has partnered with one of the most active and proven operators in the play, Gulfport Energy (NYSE: GPOR)

– Gulfport and Rice’s acreage positions are very complementary, leading to substantial efficiency gains with extended laterals

Utica Rigs Over Time (1)

The Southern Utica Core has become the most active region in the Appalachian Basin

Infrastructure Build-out Active build-out of midstream infrastructure to support

production in the Utica

Take-away capacity out of the Appalachian Basin will continue to improve

Rice’s production is expected to be substantially all dry gas and enables multiple take-away options

November 2012 August 2014

UticaFairway

MarcellusFairway

MarcellusCore

Utica Core

Total Rigs: 49 Rigs in Core: 38 Belmont Rigs: 8

UticaFairway

Industry RigsRice Acreage Position

MarcellusFairway

MarcellusCore

Utica Core

Total Rigs: 33 Rigs in Core: 6 Belmont Rigs: 0

Utica: The Newest Premier Shale Play


Very consistent and predictable well results clearly define Utica Core in the southern portion of the play Wells in Belmont and Monroe have routinely tested > 30 MMcf/d

Rice’s first well in Belmont, Bigfoot 9H, tested at a stabilized rate of 42 MMcf/d Currently producing at a restricted rate of 14 MMcf/d

Rice Energy controls 50,772 net acres in the center of Belmont County. Industry getting very strong results in WV panhandle. Pennsylvania delineation is underway from peers

__________________________Note: Initial production rates are based on operator announcements and public filings.

Gulfport: Shugert 1-2H3 BCF in 309 Days (10 MMcf/d avg.)

Belmont

Rice: 1 wellBigfoot 9H

IP: 42 Mmcfe/d676 Mmcfe in 49 Days

(14 MMcf/d avg.)

Rice: 2 wellsBlue Thunder Pad

Completing

AR: Gary 2H 2.4 BCF in 157 Days

(15 MMcf/d avg.)

Rice’s acreage is surrounded by the largest producing wells in the Utica

Rice: 5 wellsDigger PadsHz Drilling

Industry Results Confirm our Position in the Utica Core

Monroe

Gulfport Irons 1-4H 1.5 BCF in 106 Days

(14 MMcf/d avg.)

MHR Stadler A184 Mmcf in 8 Days

(23 MMcf/d avg.)

XTO Kaldor 1H1.2 BCF in 110 Days

(11 MMcf/d avg.)

Rice: 3 WellsMohawk Warrior Pad

Tophole Drilling

ECR Tippens1.3 BCF in 93 Days

(14 MMcf/d avg.)

Gulfport: Stutzman2.7 BCF in 259 Days

(10 MMcf/d avg.)

20 – 40 Mmcfe10-20 Mmcfe< 10 Mmcfe

> 40 Mmcfe

Chevron 1 WellIP: 20+ Mmcfed

Planned / In Progress

Noble

Guernsey

Harrison

Marshall

Wetzel

Rice Acreage

IP Rates Sized and Color Coded

20 – 40 Mmcfe10-20 Mmcfe< 10 Mmcfe

> 40 Mmcfe

Planned / In Progress


Bigfoot 9H Flowing Pressures – Why It’s a Big DealWellhead pressure is the leading indicator of sustainability of initial flow rates. Utica pressure regime suggests our 1.5-2.0 MMcf/d initial flow rate could be sustainable for up to 14 months, approximately 1-8 months longer than our budgeted Utica type curve

Flow rate decline whenwellhead psi = line psi

Line pressure (750-1500 psi)

Flow

Rat

e, Mc

f/d

Budget Type Curve

Well

head

Pre

ssur

e, ps

i

Bigfoot Flow Rate Projection

1 YearCumulative

5.1 Bcf

3.8 Bcf

4.9 Bcf

18 MonthCumulative

7.3 Bcf

Bigfoot 9H Actual

DaysBigfoot 9H is in the heart of our Belmont County position and representative

of the production potential from our remaining drilling locations

Flat Period Cumulative

5.9 Bcf

Flow rate decline whenwellhead psi = line psi

4.7 Bcf

6.0 Bcf


Belmont + Monroe Counties: The Utica OutliersEarly production results in Belmont and Monroe significantly outperforming the Utica as a whole

-

1,000,000

2,000,000

3,000,000

4,000,000

5,000,000

6,000,000

7,000,000

8,000,000

- 100 200 300 400 500 600 700 800 900 1,000 1,100 1,200 1,300 1,400 1,500

Cum

ulat

ive

Prod

uctio

n (M

cfe)

Days Online

Belmont Monroe Other Utica Susquehanna, PA (Marcellus)

Rice believes Belmont + Monroe could be as potent as leading Marcellus counties Rice is set for significant growth with its 50,000 acres in the center of Belmont County Ohio

__________________________Note: Production data per Ohio Department of Natural Resources.


Offset operator results mirror Rice’s internal geologic model– Core Features: Strong Point Pleasant porosity, impermeable Upper Utica cap, highly overpressured

– Essentially 100% of Rice acreage is located in a concentrated area with these characteristics

Data from initial Rice-operated wells in Belmont County very encouraging: Porosity > 14% in our target interval. Strongest in the play.

• First three horizontal wells drilled had 100% of the lateral geosteered within a 4’ sweet spot Impermeable Upper Utica cap. Important for fracture containment during completions Severely overpressured

• Pressure Gradient > 0.8 psi/ft. Calculated bottomhole pressure > 8000 psi

North South

6 MMcfe2 MMcfe 8 MMcfe 12 MMcfe 30 MMcfe

0%

6%

Rice BelmontLeasehold

Porosity 12%

__________________________Note: Initial production rates are based on operator announcements and public filings.

20 MMcfe1 MMcfe Pending Results

Utica

Point Pleasant Core

Rice Energy controls ~50,772 net acres in the heart of the high porosity Point Pleasant core in Belmont County

CRAWFORD MERCERERIE BEAVER COLUMBIANA CARROLL JEFFERSON BELMONT MONROE WASHINGTON ATHENSMERCER WASHINGTON

Point Pleasant CoreBelmont + Monroe Counties

30+ MMcfe/d

20-30 MMcfe/d

10-20 MMcfe/d5-10 MMcfe/d

0-5 MMcfe/d

High Volume Wells Predicted by Geologic Model

30-40 MMcfe/d

20-30 MMcfe/d

10-20 MMcfe/d5-10 MMcfe/d0-5 MMcfe/d

>40 MMcfe/d


5545

2819

28

10

6

0

10

20

30

40

50

60

70

0

200,000

400,000

600,000

1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39

Utica Learning Curve UpdateSystematically reducing drilling days/costs while maintaining precision wells

Improved Gas Control Procedures

Improved Mud Properties

Improved Bit Selection

Remainder of Delineation Program

• Fit-for-Purpose Deep Tophole Rig (June)• More aggressive bit selection• Deep casing elimination trial

• Fit-for-Purpose Horizontal Rig (June)• Reduction of discretionary science • Pad drilling (2H 2014)

Initial Observations from Utica Development1. Drilling

– Utica is extremely brittle, highly charged with gas, and consistent across acreage. – Very calm geologic environment leading to 100% lateral placement in 4’ sweet spot

2. Completions– Formation is highly receptive to Rice’s aggressive frac design.– First 100 stages pumped: 100% of sand placed in the ground with no issues

3. Production– Smooth and predictable production profile. 100% uptime on first well through two months

4. Landowners + Community– Very supportive. Maintaining open communication with planning

Lateral LengthWell Name

Lateral Targeting Proficiency

Completion Proficiency# Sand pumped per stage

Blue Thunder 10H: 9000’ Lateral

Bigfoot 9H: 40 Stage Frac

5 wells off two adjacent pads to be completed and turned to sales together

“Tandem Pads”

Year End 2014 Goal: < 30 Days for 9000’ Laterals


Net Unrisked Locations 271NRI Hz Ft. Inventory 2.1mm ft.PV-10 ($mm) $ 13.4IRR 70 %Undiscounted Payback 1.2 yrsD&C ($mm) $ 14.0Type Curve Assumptions120-Day IP (MMcf/d) Pre-Processed 17.1Bcf / 1000' 2.25Average Lateral Length 9,700NGL Yield (Bbls / MMcf) - Gas Mmbtu (Pre-Processed) 1,080Gas Shrink 0 %Gross EUR (Bcfe, Post-Processing) 21.8% Gas 100 %

Utica Dry – Type Well Economics (1) Utica Dry – IRR Sensitivity (2)

___________________________1. Based on $4.00/MMBtu and 100% WI. Net horizontal feet calculation based on net revenue interest assuming a 20% average royalty interest in the Utica.2. IRR is net to Rice’s ownership interest. Hedged IRR assumes 50% of production hedged at $4.00/MMBtu in the first year and 25% of production hedged at $4.00/MMBtu in the second year.

21% 41%

70%

108%

155%

33%51% 91%

115%

$3.00 $3.50 $4.00 $4.50 $5.000%

50%

100%

150%

200%

NYMEX ($ / MMBtu)Hedged IRRUnhedged IRR

Utica Wet – Type Well Economics (1) Utica Wet – IRR Sensitivity (2)

57%85%

119%

160%

210%

78%98% 142%

166%

$3.00 $3.50 $4.00 $4.50 $5.000%

50%

100%

150%

200%

250%

NYMEX ($ / MMBtu)Hedged IRRUnhedged IRR

Utica Single-Well Economics

Net Unrisked Locations 69NRI Hz Ft. Inventory 0.5mm ft.PV-10 ($mm) $ 19.6IRR 119 %Undiscounted Payback 1.0 yrsD&C ($mm) $ 8.0Type Curve Assumptions120-Day IP (MMcf/d) Pre-Processed 15.2Bcf / 1000' 2.00Average Lateral Length 9,700NGL Yield (Bbls / MMcf) 40Gas Mmbtu (Pre-Processed) 1,200Gas Shrink 15 %Gross EUR (Bcfe, Post-Processing) 21.1% Gas 78 %

Bigfoot 9H production performance indicates significant upside potential to our single-well economics. We will update EURs, type curves and single-well economics in January 2015


Midstream Assets


Midstream Overview

Washington

Colum

bia Gas (TC

O)

National Fuel G

as Supply (NFG

S)

Committed to operating our gas gathering assets to maximize transportation potential via 1 Bcf/d of firm capacity with access to premium US markets. Through YE 2014, RICE will have invested $475 million in midstream infrastructure with 4.5 Bcf/d of outlet capacity in the cores of the Marcellus and Utica shales

Rockies Express

Firm Capacity: 175 Mdth/d In-service date: Summer 2015

Texas Eastern (TETCO)

Firm Capacity: ~540 Mdth/d In-service date: Summer 2015

OH Water System

Withdrawal Capacity: 5 MMgpd Expected Savings: $500k/well In-service date: Summer 2015

Dominion Transmission

Firm Capacity: ~90 Mdth/d In-service

PA Water System

Withdrawal Capacity: 5 MMgpd Expected Savings: $500k/well In-service date: 1H15

Columbia (TCO)

Firm Capacity: ~200 Mdth/d In-service date: In-service

Dominion East Ohio

Firm Capacity: ~30 Mdth/d In-service

Texas Eastern (TETCO)

Firm Capacity: ~540 Mdth/d In-service date: 4Q14

ET Rover

Firm Capacity: 100 Mdth/d In-service date: Summer 2017

Allegheny

Marshall

Belmont

Monroe

Harrison

Jefferson

Broo

ke

Greene

Ohio


Gulfport (negotiating) Dedicated Acreage: ~17,000 gross AMI: ~60,000 acres

Midstream Recent Developments

Summary of 3rd Party Opportunities

We have entered into a letter of intent with Gulfport Energy to provide midstream services for a predominantly dry gas area covering approximately 65% of Gulfport’s acreage within our area of mutual interest (AMI)

EQT Dedicated Acreage:

~17,000 gross AMI: ~60,000 acresAntero Dedicated Acreage: ~4,000

gross AMI: ~6,000 acres

Range Johnson Pad

dedicated


TETCO

TCO

DTIDEO

REX

ET Rover

–

200

400

600

800

1,000

1,200

7/1/14 7/1/15 7/1/16 7/1/17 7/1/18 7/1/19 7/1/20

BBtu/d

Firm Transportation and Firm Sales Portfolio

For production growth assurance and net realized pricing, firm capacity is creating differentiation amongst Appalachian producers. Rice Energy was early in identifying and securing its basin-leading portfolio of firm capacity.

Expect ~100% of 2015 production and substantial majority of 2016 production to be protected by FT and FS

Firm Transport De-risks Production Growth

__________________________1. Average for remaining 2014.

Average FT & FS Portfolio (Bbtu/d)

2014 2015 2016 2017 2018 2019 2020453 811 918 958 1,003 985 938

Recently Acquired ET Rover Capacity: 100,000 MMBTU/D of capacity, 15 year contract, $0.80/MMBTU demand charge, expected in-service July 2017

(1)


46% 39% 53% 64% 53%

54%61%

47%36%

47%

($0.74) ($0.86)

($0.60)

($0.46) ($0.49)

($1.00)

($0.90)

($0.80)

($0.70)

($0.60)

($0.50)

($0.40)

($0.30)

($0.20)

($0.10)

$0.00

0%

20%

40%

60%

80%

100%

2Q14 3Q14 4Q14 2015 Average 2016 Average

Differential to NYMEX($/MMbtu)Basis Exposure

Non-Appalachia Appalachia Weighted Average Basis

Quarterly Basis Exposure

Southwest Appalachia basis exposure is significantly reduced by 4Q14 and over 60% of 2015 volumes will access attractive Gulf Coast, Midwest and TCO markets

Long-Haul Firm Transport Improves Realized Pricing

__________________________1. Non-Appalachia includes TCO, Gulf Coast, and Midwest exposure.

(1)

Nov. 14 - TETCO ELA Capacity online

In November 2014, we begin shipping 270,000 MMbtu/d from TETCO to East Louisiana, thereby shifting a significant amount of production to premium Gulf Coast pricing and significantly improving our overall average expected basis differential


$3.88 $3.50

$2.94 $0.67

$0.16 $0.13 $0.56

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

NYMEX Strip(7/1-12/31)

Less:Weighted

Avg. BasisImpact

Plus: 1,050 BTU

Gas Uplift

Plus: NYMEX&

BasisHedges

RealizedPrice

Less: G&TExpense

NetPrice

$/MMBtu

30%20%

21%

16%

13%

11%

35%51%

0% 1%

0%10%20%30%40%50%60%70%80%90%

100%

2014 2015

M2 Dom S TCO Gulf Coast Midwest

$0.56 $0.60

$0.68 $0.49

$1.23 $1.09

$- $0.20 $0.40 $0.60 $0.80 $1.00 $1.20 $1.40

7/1/14 - 12/31/14 2015

$/MMBtu

FT+FS Basis

(17%)(12%)

(35%)

(30%)

(25%)

(20%)

(15%)

(10%)

(5%)

0%

5%2014 2015% of NYMEX

TCO M2 Dom S

Gulf Coast Midwest Weighted Average

Rice’s firm transportation and sales contracts provides basis and pricing diversification

Firm Transportation, Firm Sales and Basis (cont’d)

Basis Exposure (1)

(7/1 - 12/31)

__________________________1. These amounts include approximately 115,000 MMBtu/d of firm sales contracted with a third party through October 2017, subject to annual renewal.2. NYMEX and basis strips as of 7/24/14.

Volume Weighted Basis Impact (1) (2)

Estimated 7/1-12/31/14 Realized Price Bridge (2)

52% exposed to

M2 and Dom S

37% exposed to M2 and

Dom S

All-In G&T Expense + Basis (assuming NYMEX strip) (2)

Assuming Strip Prices (-17% to NYMEX)

(7/1 - 12/31)

$0.67

17%


Financial Overview


Beta Acq. PF($ in millions) 6/30/14 Adj. 6/30/14

Cash $472 ($311) $1611st Lien Rev. Credit Fac. -- -- --Long Term DebtSenior Unsecured Notes 900 -- 900Other Debt 1 -- 1

Total Debt $901 $901Book Equity $1,190 -- $1,190

Total Capitalization $2,092 $2,092LiquidityBorrowing Base $385 $40 $425Less: Amount Drawn -- --Less: Letters of Credit (6/30) (72) (72)Plus: Cash 472 ($311) 161

Liquidity $786 $515

2Q 2014 Snapshot2Q14 Summary

Net production of 241 MMcfe/d, 84% and 15% increase over 2Q13 and 1Q14 volumes, respectively

June net production of 280 MMcfe/d

10 Marcellus wells turned to sales with an average lateral length of ~8,400 ft. that produced 132 MMcf/d gross in the month of June

Increased Pennsylvania leasehold position to 75,834 net acres, including ~22,000 completed Greene County acquisition and increased Ohio leasehold position to 50,772 net acres

RICE HAS MAINTAINED OPERATIONAL EXCELLENCE AND LIQUIDITY; CONTINUES TO BUILD AND DELINEATE CORE POSITION___________________________1. Beta Acquisition Adjustment for cash payment post 6/30/142. Management estimate. Borrowing base redetermination set for October 2014.

Capitalization and Liquidity

2Q14 SummaryNet Daily Production (MMcfe/d) 241 Net Daily Production (BBtu/d) 1,050 253 Henry Hub ($/MMBtu) $4.58Less: Basis Differential (0.74)Plus: BTU Uplift 0.19Plus: Other Revenue 0.09

Realized Pricing ($/Mcfe) - pre-hedges $4.12Realized Pricing ($/Mcfe) - post-hedges $3.68

Operating MetricsE&P Revenue $4.12Plus: Hedge Gain/(Loss) (0.45) Less: LOE & Taxes (0.34) Less: Gathering/Transportion (0.42) Less: Cash G&A (0.68) Plus/Less: Other Income / (Expense) 0.05

EBITDAX ($/Mcfe) $2.29

(1)

(2)


Update to 2014 Guidance

__________________________Note: Pro forma for ASR & Greene County acquisitions.

Rice has updated 2014E guidance to better reflect management’s current outlook Total net production range has tightened due to greater visibility of pad turn-to-sales timing Drilling and completions capital of $570 mm reflecting timing adjustments to our drilling schedule Lease operating expense is trending lower as Marcellus shifts to “development mode” SG&A has increased as a result staying ahead of our prolific production growth and an increased build-out of our midstream group

FY2014 Income Statement & Capital Expenditure Guidance UpdateUpdated 2014E

Low High

Income Statement GuidanceTotal Net Production (MMcfe/d) 260 295

% Dry Gas 100%

Heat Content 1050Lease Operating Expense ($/Mcfe) ($0.35) ($0.30)Gathering & Transportation ($/Mcfe) (0.55) (0.45)Production Taxes & Impact Fees ($/Mcfe) (0.03) (0.02)Cash G&A ($ mm) $65 $60

Net Wells Turned to Sales Updated 2014EMarcellus 34Utica 5

Total 39

Capital Expenditure Guidance ($ mm)D&C $570Midstream 265Land 385

Total ($ mm) $1,220


Commodity Hedging Summary

We employ financial instruments (primarily swaps and costless collars) to mitigate commodity price risk

Assures a base level of cash flow to reinvest in growth

Typically target hedging 50% of forecasted production for up to two years out

Add incremental hedges opportunistically beyond two years

Utilize our bank group as counterparties to avoid cash collateral and margin calls

__________________________1. Hedges as of 5/1/14.

Hedge Book (1)Strategy

60-80% of 2014 Production Guidance Hedged

7/1-YE2014 2015 2016 2017

NYMEX Henry Hub Contract SummaryNatural Gas SwapsVolume Hedged (Bbtu/d) 164 92 148 60Weighted Average Swap Price ($/MMBtu) $4.12 $4.16 $4.20 $4.24

CollarsVolume Hedged (Bbtu/d) 10 139 -- --Weighted Average Floor Price ($/MMBtu) $3.00 $3.96 -- --Weighted Average Ceiling Price ($/MMBtu) $5.80 $4.65 -- --

Deferred PutsVolume Hedged (Bbtu/d) 50 -- -- --Put Price ($/MMBTU) $4.55 -- -- --Put Premium ($/MMBTU) $0.45 -- -- --

Total Volume (BBtu/d) 224 231 148 60Weighted Average Floor ($/Mmbtu) $4.06 $4.04 $4.20 $4.24

% Swap 73% 40% 100% 100%Basis Contract SummaryTCOVolume (BBtu/d) 47 37 17 --Swap Price ($/MMbtu) ($0.27) ($0.42) ($0.42) --

Dominion SouthVolume (BBtu/d) 8 25 21 --Swap Price ($/MMbtu) ($0.79) ($0.79) ($0.79) --


Why Invest in Rice?

100% of Leasehold in Core of Marcellus and Utica100% of Leasehold in Core of Marcellus and Utica

Owned and Operated Gathering and Water Midstream Infrastructure Supports Our Upstream Operations

Owned and Operated Gathering and Water Midstream Infrastructure Supports Our Upstream Operations

Differentiated Technical Approach Has Led to Industry Leading Well ResultsDifferentiated Technical Approach Has Led to Industry Leading Well Results

Conservative Financial and Hedging Approach to Protect Downside and Lock-In Attractive Returns

Conservative Financial and Hedging Approach to Protect Downside and Lock-In Attractive Returns

Nimble and Incentivized Management and Technical TeamsNimble and Incentivized Management and Technical Teams

Top-Tier Growth With Attractive Risk-Adjusted Return ProfileTop-Tier Growth With Attractive Risk-Adjusted Return Profile

Firm Transportation Contracts De-risk Production Growth, Ensure Takeaway and Limit Appalachian Basis Exposure

Firm Transportation Contracts De-risk Production Growth, Ensure Takeaway and Limit Appalachian Basis Exposure


Appendix


1 17 22 28 44 47

70 89

131 128 154

209 241

3 5 13 22 28 35 55 58

84 110

173 177 208

275

319

-

50

100

150

200

250

300

350

4Q 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 1Q 2Q

Net Daily Production Gross Daily Production

1,127893 870 1,058

826 878 675 621 658 638 702 537 454 434

1,4371,423 1,437 1,188

1,000 999

763 927 844 878 797828 895 809

2,5642,315 2,307 2,246

1,826 1,877

1,4381,549 1,502 1,515 1,500

1,365 1,3481,243

$-

$500

$1,000

$1,500

$2,000

$2,500

$3,000


Drilling Cost per Foot Completion Cost per Foot

2 17 17 23 30 45 65 80

114 150

174

224 251

342

1 3 5 5 7 8 11

15 17 23

29 33

40 44

55

-

10

20

30

40

50

60

-

50

100150200

250300

350400


Horizontal Feet Horizontal Wells| 2013 |

Established Track Record of Drilling Proficiency

Producing Horizontal Feet and Wells (Gross) Average Daily ProductionMMcf/dFeet (‘000)

Wells

Average Lateral Length (2) Average PA Drilling & Completion Cost Per Lateral Foot

Proven track record of growing production, reducing costs and improving drilling efficiency

NA (1)

_______________________1. No wells brought online in Q3 2011.2. Well data based on IP date.

| 2011 | | 2012 | 20142010| 2011 | | 2012 | | 2013 | 20142010

| 2011 | | 2012 | | 2013 | 20142010

# Rigs 2 2 2 2 2 2 2 2 2 2 3 4 4 3 2

2,444 3,281

5,731 6,286 6,691

8,452 24.4

13.3

7.6 5.8 4.5 4.5

–

5

10

15

20

25

30

–1,0002,0003,0004,0005,0006,0007,0008,0009,000

2010 2011 2012 2013 1Q14 2Q14

Drilli

ng D

ays

Later

al Le

ngth

(feet)

Avg. Lateral Ft. Avg. Hz. Drilling Days


374

152 193 53

560

190 270

69

104%

58%70%

119%

0%

20%

40%

60%

80%

100%

120%

140%

–

100

200

300

400

500

600

Marcellus W Greene Utica Dry Utica Wet

IRR

Net

Loc

atio

ns

Risked Locations Unrisked Locations IRR

Marcellus Inventory: 12+ Years, weighted average single well return of ~92%– Type curve de-risked by historical production

Utica Inventory: 15+ Years, weighted average single well return of 78%– First Utica well, Bigfoot 9H, tracking above

expectations

Difference driven by historical

gathering fee

Deep Inventory of High Returning Projects

___________________________Note:. Net horizontal feet calculation based on net revenue interest assuming a 18.5% average royalty interest in the Marcellus and 20.0% average royalty interest in the Utica. See slide entitled “Additional Disclosures” on detail regarding Rice’s methodology for the

calculation of net unrisked and risked locations1. Economics based on $4.00/Mmbtu and 100% WI.2. Acquired acreage dedicated to Access Midstream Partners. Historical gathering fee of $0.45/mmbtu and historical compression fee of $0.12/mmbtu. Rice currently in negotiations with Access to determine terms of new gathering agreement.

(2)

W. Greene Utica UticaMarcellus Acq. Dry Wet

Pre-Tax NPV10 ($MM) $8.5 $6.1 $13.4 $19.6Pre-Tax IRR 104% 58% 70% 119%Net F&D ($/mcf) $0.84 $0.76 $0.80 $0.81

Net Risked Locations 374 152 193 53Net Unrisked Locations 560 190 270 69Undiscounted Unrisked Value ($MM) $4,763 $1,159 $3,617 $1,352Unrisked NRI HZ Ft Inventory (mm ft) 2.7 1.1 2.1 0.5

Type Curve Assumptoins120-Day IP (MMcf/d) Pre-Processed 13.4 15.6 17.1 15.2Bcf/1,000' 1.94 1.94 2.25 2.00Average Lateral Length (Ft) 6,000 7,000 9,700 9,700NGL Yield (Bbls/MMcf) – – – 40.0Modeled BTU 1,050-1,100 1,090 1,080 1,200Shrink – – – 15%Gross EUR (Bcfe) 11.6 13.6 21.8 21.1Well Cost ($MM) $8.0 $8.4 $14.0 $14.0Historical Gathering + Compression Fee ($/MMBTU) – $0.57 – –


2Q 2014 Adjusted EBITDA Reconciliation

__________________________Note: Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDAX as net income (loss) before interest expense or interest income; income taxes; write-down of abandoned leases; depreciation, depletion and amortization; amortization of deferred financing costs; equity in (income) loss of our joint ventures; derivative fair value (gain) loss, excluding net cash receipts on settled derivative instruments; non-cash compensation expense; (gain) loss from sale of interest in gas properties; (gain) loss on acquisition; (gain) loss on extinguishment of debt; write-off of deferred financing costs; and exploration expenses. Adjusted EBITDAX is not a measure of net income as determined by United States generally accepted accounting principles, or GAAP. Gives pro forma effect to (i) our initial public offering and the completion of the corporate reorganization in connection with our initial public offering and (ii) the consummation of our acquisition of the remaining 50% interest in our Marcellus joint venture from Alpha Natural Resources, Inc., each of which was completed on January 29, 2014, as if such transactions had been completed on the first day of the period presented.1. The adjustments for the derivative fair value (gains) losses and net cash receipts on settled commodity derivative instruments have the effect of adjusting net income (loss) for changes in the fair value of derivative instruments, which are recognized at the end

of each accounting period because we do not designate commodity derivative instruments as accounting hedges. This results in reflecting commodity derivative gains and losses within Adjusted EBITDAX on a cash basis during the period the derivatives settled.

2. Represents gain incurred on the purchase of the remaining 50% interest in our Marcellus joint venture.

Three Months Ended Six Months Ended($ in thousands) June 30, 2014 June 30, 2014Adjusted EBITDAX reconciliation to net income (loss):

Net income (loss) $(7,917) $121,538Interest expense 15,941 22,983Depreciation, depletion and amortization 32,552 58,059Amortization of deferred financing costs 532 1,021Amortization of intangible assets 340 340Equity in loss of joint ventures -- 2,656Derivative fair value (gain) loss (1) 11,198 31,578Net cash receipts on settled derivative instruments (1) (9,795) (20,953)Gain on purchase of Marcellus joint venture (2) -- (203,579)Non-cash stock compensation expense 1,125 1,216Non-cash incentive unit expense 1,474 75,276Income tax (benefit) expense (4,593) 4,782Loss on extinguishment of debt 3,001 3,144Write-off of deferred financing costs 6,060 6,896Exploration expenses 473 959

Adjusted EBITDAX $50,391 $105,916


Cautionary StatementsFORWARD-LOOKING STATEMENTSThis presentation and the oral statements made in connection therewith may contain “forward looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical fact, regarding Rice Energy’s strategy, future operations, financial position, estimated revenues and income/losses, projected costs, prospects, plans and objectives of management are forward-looking statements. These statements often include the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on Rice Energy’s current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. Rice Energy assumes no obligation to and does not intend to update any forward looking statements included herein. Rice Energy cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond their control, incident to the exploration for and development, production, gathering and sale of natural gas, natural gas liquids and oil. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under “Risk Factors” in Rice Energy’s Form 10-K filed on March 21, 2014 and other filings with the Securities and Exchange Commission. Should one or more of these risks or uncertainties occur, or should underlying assumptions prove incorrect, Rice Energy’s actual results and plans could differ materially from those expressed in any forward-looking statements.

This presentation has been prepared by Rice Energy and includes market data and other statistical information from sources believed by Rice Energy to be reliable, including independent industry publications, government publications or other published independent sources. Some data are also based on Rice Energy’s good faith estimates, which are derived from its review of internal sources as well as the independent sources described above. Although Rice Energy believes these sources are reliable, it has not independently verified the information and cannot guarantee its accuracy and completeness.

Certain of Rice Energy's wells are named after superheroes and monster trucks, some of which may be trademarked. Despite their size and strength, Rice Energy's wells are in no manner affiliated with such superheroes or monster trucks.

Initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels. In particular, production from horizontal drilling in shale oil and natural gas resource plays and tight natural gas plays that are stimulated with extensive pressure fracturing are typically characterized by significant early declines in production rates.

NON-PROVEN OIL AND GAS RESERVESThe SEC permits oil and gas companies, in their filings with the SEC, to disclose proved reserves, which are reserve estimates that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions and certain probable and possible reserves that meet the SEC’s definition for such terms. We may use certain broader terms such as EUR (estimated ultimate recovery of resources), and we may use other descriptions of volumes of potentially recoverable hydrocarbon resources throughout this presentation that the SEC does not permit to be included in SEC filings. These broader classifications do not constitute reserves as defined by the SEC, and we do not attempt to distinguish these classifications from probable or possible reserves as defined by SEC guidelines.

Our estimates of EURs have been prepared by our independent reserve engineers. These estimates are by their nature more speculative than estimates of proved, probable and possible reserves and accordingly are subject to substantially greater risk of being actually realized, particularly in areas or zones where there has been limited or no drilling history. We include these estimates to demonstrate what we believe to be the potential for future drilling and production by the company. Actual locations drilled and quantities that may be ultimately recovered from our properties will differ substantially. In addition, we have made no commitment to drill all of the drilling locations which have been attributed to these quantities. Ultimate recoveries will be dependent upon numerous factors including actual encountered geological conditions, the impact of future oil and gas pricing, exploration and development costs, and our future drilling decisions and budgets based upon our future evaluation of risk, returns and the availability of capital and, in many areas, the outcome of negotiation of drilling arrangements with holders of adjacent or fractional interest leases. Estimates of resource potential and other figures may change significantly as development of our properties provide additional data and therefore actual quantities that may ultimately be recovered will likely differ from these estimates.

Our forecast and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells, the undertaking and outcome of future drilling activity and activity that may be affected by significant commodity price declines or drilling cost increases.


Determination of Identified Drilling Locations as of June 30, 2014 pro forma for ASR buy-in (closed 1/29/14) and Greene County acquisition (closed 8/1/14)

Our gross (net) identified drilling locations are those drilling locations identified by management based on the following criteria:

Drillable Locations – These are mapped locations that our Vice President of Exploration & Geology has deemed to have a high likelihood as being drilled or are currently in development but have not yet commenced production. With respect to our Pennsylvania acreage, pro forma for the ASR buy-in and the Greene County acquisition, we had 330 gross (301 net) pro forma drillable Marcellus locations and 134 gross (117 net) pro forma drillable Upper Devonian locations. With respect to our Ohio acreage, we had 636 gross (191 net) drillable Utica locations, all of which are located within the contract areas covered by our Development Agreement and AMI Agreement with Gulfport.

Estimated Locations – These remaining estimated locations are calculated by taking our total acreage, less acreage that is producing or included indrillable locations, and dividing such amount by our expected well spacing to arrive at our unrisked estimated locations which is then multiplied by a risking factor. For our existing Marcellus acreage position and acreage acquired through the ASR buy-in, we assume these Marcellus locations have 6,000 foot laterals and 600 foot spacing between Marcellus wells which yields approximately 80 acre spacing. For the Greene County acquisition, we assume these Marcellus locations have 7,000 foot laterals and 600 foot spacing between Marcellus wells which yields approximately 100 acre spacing. We assume these Upper Devonian locations have 6,000 foot laterals and 1,000 foot spacing between Upper Devonian wells which yields approximately 140 acre spacing. We assume Utica locations have 8,000 foot laterals and 600 foot spacing between Utica wells which yields approximately 110 acre spacing.

With respect to our Pennsylvania acreage, we multiply our unrisked estimated Marcellus and Upper Devonian locations by a risking factor of 50% to arrive at total risked estimated locations. As a result, we had 233 gross (225 net) pro forma estimated risked Marcellus locations and 148 gross (144 net) pro forma estimated risked Upper Devonian locations. With respect to our Ohio acreage, we multiply our unrisked estimated locations by a risking factor of approximately 37% to arrive at total risked estimated locations. We then apply our assumed working interest for such location, calculated by applying the impact of assumed unitization on the underlying working interest as well as, in the case of locations within the AMI with Gulfport, the applicable participating interest. As a result, we had 139 gross (55 net) estimated risked Utica locations. Estimated locations include ununitized locations that have been risked (50% in the Marcellus, 37% in the Utica) to take into account the risk of forming drilling units.

Risked Locations – Consist of Drillable Locations and Risked Estimated Locations. We assume 563 gross (526 net) risked Marcellus locations. We assume 282 gross (261 net) risked Upper Devonian locations. We assume 775 gross (246 net) risked Utica locations.

Unrisked Locations – Consist of Drillable Locations and Unrisked Estimated Locations. We assume 797 gross (750 net) unrisked Marcellus locations. We assume 430 gross (406 net) unrisked Upper Devonian locations. We assume 1,011 gross (339 net) unrisked Utica locations.

Additional Disclosures

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Rice Energy Investor Presentation - August 11, 2014